Methods of stabilizing shale surface to minimize proppant embedment and increase proppant-pack conductivity

ABSTRACT

Embodiments of the invention relate to a method of treating a subterranean formation comprising shale comprising forming a fluid comprising potassium acetate, and introducing the fluid to a surface of the subterranean formation comprising shale, wherein geomechanical weakening of the formation is lower than if the formation were not in contact with the fluid. Embodiments of the invention relate to a method of treating a subterranean formation comprising shale, comprising forming a fluid comprising potassium chloride and ammonium acetate; and introducing the fluid to a surface of the subterranean formation comprising shale, wherein geomechanical weakening of the formation is lower than if the formation were not in contact with the fluid.

PRIORITY

The application claims priority to U.S. Provisional Patent Application Ser. No. 61/342,931, filed Apr. 21, 2010, entitled, “Methods of Stabilizing Shale Surface to Minimize Proppant Embedment and Increase Proppant-Pack Conductivity,” and incorporated by reference herein.

FIELD

Embodiments of the invention relate to stabilizing the integrity of subterranean formation surfaces, particularly surfaces that comprise clay.

BACKGROUND

Shale based reservoirs are typically included in the category of unconventional reservoirs, which also includes tight (ultra low-perm) sandstones and coalbed methane. Shale reservoirs may have some properties of both (ultra-low matrix perm, combination of compressed gas and adsorbed gas, geochemical considerations) but may not necessarily behave as either.

When evaluating typical logging suites for a commercial shale gas, it may be noted the lithology is dominated by a combination of silica, carbonate, clays and organic content in addition to other trace minerals. These are not the intervals that are so problematic for drillers which have dominated the literature prior to the shale gas revolution but rather they are composed of a unique set of conditions which have to be understood and managed in order to make a successful producing well. One thing that is consistent is that shale gas reservoirs need hydraulic fracturing treatments in order to produce at commercial and economic rates/volumes.

The Haynesville Shale formation of east Texas and northwest Louisiana was a departure from the earlier shale gas field developments in that it was substantially deeper (11,000-13,000 ft), over-pressured (˜0.8 psi/ft average) with a high frac gradient (closure pressure/stress) and BHST greater than 300 degF. Petrophysically and geomechanically the Haynesville Shale has clay content on the high end and a Young's Modulus towards the lower end of other shale plays as illustrated by the following.

Formation Brinell Hardness Woodford 43 Marcellus 32 Haynesville 18 Bossier 12 Barnett 80 Carthage lime 82 Ohio sandstone 34 Alabama coal 15 Floyd 25

The combination of these properties means that the Haynesville Shale is more difficult to fracture stimulate with conventional slickwater treatment designs (higher surface pressure, harder to develop adequate frac width for proppant placement and poorer proppant transport) but the biggest challenge has been achieving adequate proppant-pack conductivity. The high closure stress has resulted in the use of higher strength proppants. The higher fracture gradient has resulted in the use of higher viscosity fluids in some cases and/or smaller mesh size proppant to avoid a premature screenout. Another big difference has been the determination of significant proppant embedment in the Haynesville Shale. This is due to the combination of high closure stress, higher strength proppant, geomechanical properties and the geochemical behavior of the shale surface due to contact with fracturing fluids.

SUMMARY

Embodiments of the invention relate to a method of treating a subterranean formation comprising shale comprising forming a fluid comprising potassium acetate, and introducing the fluid to a surface of the subterranean formation comprising shale, wherein geomechanical weakening of the formation is lower than if the formation were not in contact with the fluid. Embodiments of the invention relate to a method of treating a subterranean formation comprising shale, comprising forming a fluid comprising potassium chloride and ammonium acetate; and introducing the fluid to a surface of the subterranean formation comprising shale, wherein geomechanical weakening of the formation is lower than if the formation were not in contact with the fluid.

FIGURES

FIG. 1 is a plot of Brinell hardness after exposure to fracturing versus time for a sample of Haynesville shale.

FIG. 2 is a plot of shale stability test results for an embodiment.

FIG. 3 is a plot of swellmeter test results.

DESCRIPTION

At the outset, it should be noted that in the development of any such actual embodiment, numerous implementation—specific decisions must be made to achieve the developer's specific goals, such as compliance with system related and business related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. In addition, the composition used/disclosed herein can also comprise some components other than those cited. In the summary of the invention and this detailed description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. Also, in the summary of the invention and this detailed description, it should be understood that a concentration range listed or described as being useful, suitable, or the like, is intended that any and every concentration within the range, including the end points, is to be considered as having been stated. For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10. Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to only a few specific, it is to be understood that inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors possessed knowledge of the entire range and all points within the range.

The statements made herein merely provide information related to the present disclosure and may not constitute prior art, and may describe some embodiments illustrating the invention.

A series of tests were conducted in which Haynesville shale samples and the broken fracturing fluid mixture were placed in a pressure bomb at 300 deg F. The broken fluid refers to use of chemicals known to function as a breaker for the particular fluid being tested such that the viscosity of the fluid is reduced to, or close to, the viscosity of the base fluid, which in the case of this particular test is water. In the case of polymeric, natural or synthetic, fluid systems the “breaker” will act to cleave the polymer chain into shorter segments thus reducing the molecular weight and causing the fluid system to reduce in viscosity. The “breaker” may also act to break bonds of other chemicals, such as crosslinkers, to the polymer which also causes a reduction in viscosity. The shale in the broken fracturing fluid showed a major decrease in Brinell hardness at 30 days which held constant for 60 days (FIG. 1). This shows that the samples of Haynesville shale softened substantially, that is, experienced geomechanical weakening over a long period when exposed to broken fracturing fluid. This weakening is undesirable. As weakening increases, processes for introducing proppant to a formation to prop open a fracture transform into processes for embedding proppant into the mushy, soft formation surface. That is, the interstitial space between the layers of silica and alumina in clay become enlarged and distorted and the solid, relatively homogeneous formation surface becomes fragmented as the polar solvents (such as water) interact with the clay's cations. This fragmented surface provides an ineffective barrier or rigid surface to support the proppant and the proppant randomly aligns, agglomerates, and/or embeds along the amorphous, heterogeneous region between rigid, relatively solvent-free formation and formation fracture voids. The resulting decrease in production is due to the reduction of fracture conductivity (defined as the permeability of the proppant-pack multiplied by the width of the propped hydraulic fracture) as a result of proppant embedment. The embedment of proppant itself reduced the propped fracture width and the process of proppant embedment in turn results in displacement of formation material that enters the proppant-pack and subsequently reduces the permeability even further. In such circumstances, the resulting overall formation productivity is reduced and the proppant pack has reduced permeability and conductivity may require introducing additional proppant, and may experience reduced fracture profile integrity.

Thus, minimizing the geomechanical weakening to result in improvement of proppant-pack conductivity by mitigation of the proppant embedment is one focus of some embodiments of the invention. Introducing a fluid containing potassium acetate or a combination of potassium chloride and ammonium acetate to stabilize the surface of the shale formation and mitigate or eliminate the geomechanical weakening caused by the interaction of the shale and the fracturing fluid(s) being pumped. As a result of this the embedment of proppant will be diminished or eliminated resulting in greater proppant-pack conductivity.

As stated above, some embodiments relate to stabilizing and maintaining or improving the stability of the shale formation along the hydraulic fracture-face in order to reduce or eliminate the amount of proppant embedment. While this problem is somewhat analogous to the wellbore stability methodology modifying parameters to various degrees in ways that may not be completely consistent with the wellbore stability approach are some of the techniques consistent with embodiments of the invention. The basic intent is to 1) provide a fracturing fluid solution capable of diffusing, imbibing or otherwise migrating into the shale in order to exchange at the various clay platelets in order to minimize or eliminate the swelling pressure; 2) provide a fracturing fluid solution with the ability to chemically react with the shale in order to internally (within the matrix) increase the cementation forces; 3) control the shale water saturation near the fracture-face, which in-turn controls the pore pressure and increases the strength and effective stress (through the mechanism of cohesion and friction angle). As shale properties will vary from reservoir to reservoir (even within the same reservoir) the degree of which each of these components contributes to the final solution will no doubt vary.

Generally, a fluid is selected to facilitate delivery of potassium acetate to the space between the layers in the clay components of the shale. Specifically, the acetate helps deliver the potassium to fill the space. Potassium has an ionic radius that fills the space more effectively than other materials. Polar organic fluids help with this behavior. Fluids may include glycerine, ethylene glycol, diethylene glycol, triethylene glycol, propylene glycol, dipropylene glycol and tripropylene glycol. The fluid may also include nitrogen, carbon dioxide, air and a mixture thereof.

Some embodiments may benefit from a potassium acetate fluid or potassium chloride and ammonium acetate fluid or a combination of potassium acetate, potassium chloride, and ammonium acetate. Quaternary amines, such as tetramethyl ammonium chloride (TMAC) may be used in combination with the potassium acetate or potassium chloride and ammonium acetate. Other quaternary amines include ammonium chloride, tetraalkyl ammonium salts, choline chloride, dimethyl diallyl ammonium chloride, triethanol amine methyl chloride, ethoxylated diamine, amphoteric amines, hexamethylene diamine/salts cyclohexyldiamines, polyethylene imine salts, oligomeric ether amines/salts, oligomeric imines, polycationic PHPA, or a combination thereof.

In some embodiments, potassium acetate concentration or potassium chloride and ammonium acetate concentration are selected based on formation characteristics. Some formation characteristics include clay concentration, formation fracture model, type of clay, surface area of the formation, and a combination thereof.

A pressure of the fluid may be selected to be at a pressure to fracture in the formation. In some embodiments, the following processes may benefit from using the fluid: hydraulic fracturing, matrix injection, drilling, completions, sand control, perforations, or a combination thereof.

In some embodiments, reduced geomechanical weakening is measured by proppant embedment depth, proppant pack conductivity or permeability, and/or Brinell hardness.

One illustrative embodiment involves the use of potassium acetate (KC₂H₃O₂) in the fracturing fluid formulation to provide the mitigation or elimination of geomechanical weakening of the shale as a result of the interaction with the fracturing fluid system. This is illustrated in the following example.

Example 1

Tests were performed for the purpose of determining the effect of various clay control additives on the behavior of shale samples.

Procedure: Haynesville Shale was recovered from the shale shaker during the drilling process. The shale was allowed to dry and then screened on a Tyler RoTap for 30 minutes. The plus 10-mesh material was collected and used in tests of its relative stability when in contact with various inhibitors. The test involved placing 20 grams of shale in a container that was immersed in a sonic bath at 50 degC for a period of one hour. After the sonic bath exposure was completed, the shale was rescreened with the percent retained on 10-mesh, the material smaller than 10-mesh but greater than 200-mesh was measured as well as the amount of material smaller than 200-mesh. Tests were conducted on a host of potential shale stabilizers at different concentrations (by weight percent).

This test was selected because the results could be reproduced with but a small statistical error and the relative performance results of different inhibitors followed a reasonably intuitive pattern. Other test methods such as hot rolling destroyed the cuttings—largely due to autogenously grinding. Alternatively, high temperature static tests did not cause sufficient degradation to discern differences within an acceptable statistical error. The statistical error with this procedure was unexpectedly low.

Results: The results of this testing indicate better performance for potassium acetate (Blend A FIG. 2; Table 1) compared with potassium chloride, calcium chloride and tetramethyl ammonium chloride (TMAC). The main observation is that Haynesville shale exposed to potassium acetate solution exhibited less dispersion and maintained integrity compared to potassium chloride, calcium chloride and TMAC.

TABLE 1 Shale Stability Test Results Percentage by Weight Percent of Shale Retained KCl 2.5 40.74 5.0 59.91 7.5 71.45 10.0 73.69 15.0 80.42 TMAC* 2.5 13.18 5.0 27.18 7.5 31.98 10.0 45.43 15.0 63.79 Calcium Chloride 2.5 24.94 5.0 39.89 7.5 45.97 10.0 57.76 15.0 58.90 Potassium Acetate Blend A (potassium acetate and TMAC) 2.5 68.46 5.0 81.56 7.5 88.21 10.0 94.06 15.0 94.29 Potassium Acetate Blend B (potassium acetate) 2.5 56.34 5.0 81.45 7.5 90.29 10.0 90.46 15.0 91.91 *Percentage “as-is” or as 50% TMAC

Example 2

FIG. 3 displays the bentonite-fluid interaction for the fluid during the entire 18.3 hours period for the linear swellmeter test and shows the trend between the four fluids.

All of the base fluids show a positive slope which confirms an immediate and constant interaction between the clay and the base fluid (FIG. 3). The black curve of fresh water had the highest expansion rate—more than doubling its axial dimension. The red curve of glycol showed the highest rate of shale stabilization over most of the test period. Another observation is glycol may be useful as a shale stabilizer in some embodiments of the invention as well.

As seen in FIG. 3, stabilization began around 275 minutes into the test with a maximum expansion of 46% when the glycol formulation was tested. The amount of expansion stayed in a straight line of zero slope indicating a very positive balanced activity resulting in an ideal condition for wellbore stability. As seen above, glycol and potassium acetate were effective in altering the geomechanical properties of the rock to retain hydraulic fracture conductivity. The yellow curve of potassium acetate stabilized around 350 minutes into the test with a 58% expansion. This fluid also exhibits some shale stability although not quite as good as the glycol-based fluid. The black curve of fresh water and the blue curve of the glucose+surfactant fluids showed very clearly that these fluids do not contribute to the stability of this shale sample. The blue glucose+surfactant base initially acted as an adequate shale inhibitor, however after 330 minutes it was surpassed by the Glycol and after 500 minutes by the potassium acetate base fluid. While performing better than fresh water, its positive slope throughout the test showed a limited capacity as an effective shale stabilizer.

It is apparent that a combination of potassium acetate with polar organic fluid may, in some cases, provide better shale stabilization than potassium acetate alone. Some examples of polar fluids are selected from the group consisting of glycerine, ethylene glycol, diethylene glycol, triethylene glycol, propylene glycol, dipropylene glycol and tripropylene glycol.

As stated above, methods are related to providing better hydraulic fracture conductivity in shale gas wells. One example is for the Haynesville Shale where the higher clay content may react to a greater degree with the fracturing fluid and creates a worse case for proppant embedment into the fracture-face, which may lead to less hydraulic fracture conductivity (less fracture width and less proppant-pack permeability). Additives used in drilling fluids in order to diminish shale-fluid interaction may present a number of difficulties (wellbore stability, sloughing resulting in stuck drill pipe, wellbore breakout making log evaluation almost impossible for pad devices, etc.). While clay control additives are added to fracturing fluids to prevent clay swelling, clay migration, etc., this is primarily to prevent permeability damage in the reservoir due to clay swelling and migration and clay particles migrating and plugging up portions of the proppant-pack. This, however, is different from the methods of the invention, claimed below. 

1. A method of treating a subterranean formation comprising shale, comprising: forming a fluid comprising potassium acetate; and introducing the fluid to a surface of the subterranean formation comprising shale; wherein geomechanical weakening of the formation is lower than if the formation were not in contact with the fluid.
 2. The method of claim 1, wherein a pressure of the fluid during the introducing is at a pressure to fracture in the formation.
 3. The method of claim 1, wherein the fluid comprises a polar organic fluid.
 4. The method of claim 3, wherein the fluid comprises glycerine, ethylene glycol, diethylene glycol, triethylene glycol, propylene glycol, dipropylene glycol and tripropylene glycol.
 5. The method of claim 1, wherein the geomechanical weakening is measured by proppant embedment depth.
 6. The method of claim 1, wherein the geomechanical weakening is measured by proppant pack conductivity or permeability.
 7. The method of claim 1, wherein the geomechanical weakening is measured by Brinell hardness.
 8. The method of claim 1, wherein the concentration of the potassium acetate is selected based on formation characteristics.
 9. The method of claim 8, wherein the formation characteristics are selected from the group consisting of clay concentration, formation fracture model, type of clay, surface area of the formation, and a combination thereof.
 10. The method of claim 1, wherein the fluid comprises nitrogen, carbon dioxide, air and a mixture thereof.
 11. The method of claim 1, wherein the fluid further comprises a viscosifier, crosslinker, scale inhibitor, biocide, foamers, defoamers, anti-foamers, emulsifiers, de-emulsifiers, surfactants and/or a combination thereof.
 12. The method of claim 1, wherein the contacting is selected from the group consisting of hydraulic fracturing, matrix injection, completions, sand control, perforations, or a combination thereof.
 13. The method of claim 1, wherein the fluid further comprises a quaternary amine.
 14. The method of claim 1, wherein the quaternary amine is tetramethyl ammonium chloride.
 15. A method of treating a subterranean formation comprising shale, comprising: forming a fluid comprising potassium chloride and ammonium acetate; and introducing the fluid to a surface of the subterranean formation comprising shale; wherein geomechanical weakening of the formation is lower than if the formation were not in contact with the fluid.
 16. The method of claim 15, wherein a pressure of the fluid during the introducing is at a pressure to fracture in the formation.
 17. The method of claim 15, wherein the fluid comprises glycerine, ethylene glycol, diethylene glycol, triethylene glycol, propylene glycol, dipropylene glycol and tripropylene glycol.
 18. The method of claim 15, wherein the geomechanical weakening is measured by proppant pack conductivity or permeability or Brinell hardness or a combination thereof.
 19. The method of claim 15, wherein the concentration of the potassium chloride and ammonium acetate is selected based on formation characteristics, wherein the formation characteristics are selected from the group consisting of clay concentration, formation fracture model, type of clay, surface area of the formation, and a combination thereof.
 20. The method of claim 15, wherein the fluid further comprises a quaternary amine. 